Keywords

These keywords were added by machine and not by the authors. This process is experimental and the keywords may be updated as the learning algorithm improves.

5.1 Foundation Installation

The methods for installing foundations are dictated by the foundation type. Within a foundation category, some variance exists in the methods employed, but the differences are relatively minor. We focus on monopiles and jackets as they are the most relevant to the U.S. market.

5.1.1 Monopiles

Monopiles may be transported to site by the installation vessel, they may be barged to the site, they may be transported by a feeder vessel, or they may be capped and wet towed (i.e. floated using their own buoyancy). The choice depends on the size and weight of the monopile, the variable deck load and crane capacity of the installation vessel, the distance to shore, and environmental conditions. Large installation vessels with heavy-lift cranes may be able to carry several monopiles from port and lift them into place. In contrast, smaller vessels with lower deck loads or low capacity cranes may require a wet tow or barge system.

After arrival on site the pile is upended so that it is sitting vertically on the seabed. This is accomplished by a crane and/or a specialized pile gripping device and is the step which usually defines the required crane capacity (Fig. 5.1). A hydraulic hammer is placed on top of the pile and the pile is driven into the seabed to a predetermined depth (Fig. 5.2). The time to drive the pile depends on the soil type, pile diameter and thickness, and the weight of the hammer. A rocky subsurface may prevent driving operations, in which case a drill will be inserted into the pile to drill through the substrate. At the conclusion of pile installation, the pile extends from several dozen meters below the mudline, to just above the water line. The depth the pile is driven is determined by the soil type and design load, and typically about 30–50% of the total length is below the mudline.

Fig. 5.1
figure 1

Monopile being lifted off the deck. Source Chris Laurens/Vattenfall

Full size image
Fig. 5.2
figure 2

Hammer placed on the top of a monopile before driving. Source Chris Laurens/Vattenfall

Full size image

After the monopile is secured in the seabed, a transition piece is lifted and grouted onto the pile (Fig. 5.3). The transition piece is typically installed immediately after piling by the same vessel that drove the pile, but if two vessels are employed in an “assembly-line” installation, a separate vessel may follow behind the monopile installation vessel and install the transition piece. The transition piece typically starts in the water column above the mudline and extends several meters above the top of the monopole. A side dumping barge or other utility vessel may be used to place rocks around the monopile to guard against erosion (scour protection).

Fig. 5.3
figure 3

Transition piece being installed over monopile at Horns Rev 2. Source DONG A/S

Full size image

5.1.2 Jackets and Tripods

Jackets and tripods are barged from the fabrication yard to the construction site and are lifted into place (Fig. 5.4). The piles used to secure jackets and tripods to the seafloor are significantly smaller in diameter and length than monopile foundations because the mass of the jacket is better suited to hold the structure in place. Piles are either driven through sleeves at each corner of the foundation or the foundation may be placed over pre-driven piles. The sleeves are grouted to the pile or may be deformed to hold the jacket or tripod in place. The transition piece may be pre-attached to the foundation to save a lifting operation. For moderate water depths (30–50 m) jackets and tripods weigh between 500 and 800 tons. In the past, jackets have been installed by heavy-lift vessels, but some newbuild elevating vessels also have the lift capacity to place these foundations. Scour protection is less critical for jackets and tripods than for monopiles.

Fig. 5.4
figure 4

The Thialf placing a foundation at Alpha Ventus. Source Alpha Ventus

Full size image

5.1.3 Factors Impacting Installation

Foundation type will impact the time required for installation. Jackets and tripods take longer to install than monopiles because they are heavier, more complex, and more piles must be lifted and driven into place. Soil type can impact installation time because if hard rock exist below the mudline, piles will need to be drilled. If the surface is erodible, scour protection will be required which will increase the vessel spread and add time to installation. Soil type and maximum design loads also determine the required insertion depth to maintain a stable foundation.

If the installation vessel transports the foundations, the distance to port, vessel speed, and the number of foundations carried per trip determines the travel and loading time. Installation vessel travel time may be eliminated by transporting foundations on barges or towing them to site. The number of installations impacts both the total time and the time required per foundation.

Ideally, offshore work would occur in the seasons with the most favorable weather, however, this is frequently not possible and work often occurs in the winter where weather downtime is more common. Foundation installation is not as sensitive to wind conditions as turbine installation, but work during the winter will be associated with weather delays. In New England and the U.S. Mid-Atlantic, winter weather is not as severe as in the North Sea, but may still cause delays.

5.1.4 Proposed U.S. Foundation Installation Methods

U.S. foundation installation is expected to follow the European experience. Monopiles will be the preferred choice in shallow water and jackets or tripods will be the preferred choice in deeper water. Sites close to shore and in shallow water are less expensive and risky than deepwater sites and monopiles will predominate in the near term. Gravity foundations are unlikely to see any significant use in U.S. waters. It is possible that deepwater, floating foundations will one day become commercially and technically viable, but a considerable period of refinement is required before this will occur.

In the Cape Wind project, developers have proposed barging 3–4 monopiles per trip from Quonset, Rhode Island, 63 miles to Nantucket Sound. A jackup barge with crane will lift the monopiles from the transport barge and place them in position for pile driving operations. After the foundation is secured, a transition piece will be lifted and set atop the foundation and grouted [1].

5.2 Turbine Installation

Turbines are installed after foundations are in place. Installation may be done by the same vessel that installed the foundations or a different vessel may be used.

5.2.1 Transport

Most frequently, a single vessel both transports the turbine components and performs installation. Feeder vessels have also been used to transport turbine components, but this approach has not been as popular because of the risk associated with offshore transfers. When a feeder vessel is used, it often elevates to eliminate vessel movements. The decision to use a feeder vessel will depend largely on the transit speed and costs of the installation vessel, the deck load, the size of the turbine components, and the distance to shore.

5.2.2 Installation

There are a large number of options for turbine installation. When delivered, turbines typically consist of seven individual components, including three blades, at least two tower sections, the nacelle, and the hub. Some degree of onshore assembly is performed to reduce the number of offshore lifts and the degree of pre-assembly will impact vessel selection and installation time. Offshore lifts are risky and are susceptible to delay due to wind speeds, so preference is usually to maximize onshore assembly.

The methods used for offshore turbine installation are classified in terms of the number of lifts required as shown in Fig. 5.5

Fig. 5.5
figure 5

Diagrammatic representation of installation methods

Full size image
  1. 1.

    Nacelle and hub joined onshore. The tower is installed separately in two lifts, followed by the nacelle with the rotor hub preattached. All three blades are lifted separately. This method involves little onshore assembly and was used at Sprogo and Lynn and Inner Dowsing. At Lynn and Inner Dowsing this method was chosen because there was a long distance between the port and the offshore site and the method allowed for an efficient use of deck space permitting a large number of turbine components to be carried in a single trip.

  2. 2.

    Tower assembled onshore. The tower is assembled onshore and installed in a single lift. The nacelle and hub are lifted together and all three blades are installed separately. This method was used at Rhyl Flats and Burbo Bank (Fig. 5.6). As in Method 1, it has the disadvantage of requiring separate lifts for each blade which are susceptible to delays due to high winds. However, since the blades are not preassembled, they can be transported more easily, potentially allowing for a larger number of turbine components to be carried in the same deck space. Other than the deck area savings associated with not preassembling rotors, there is little reason to lift blades separately as the assembled rotor is unlikely to weigh more than the nacelle and would therefore not be the weight limiting lift.

    Fig. 5.6
    figure 6

    Installation of a nacelle and hub at Burbo Bank. Source Siemens

    Full size image
  3. 3.

    Rotor assembled onshore. The tower is transported offshore in two pieces and lifted in two lifts. The nacelle is lifted separately. The rotor and all three blades are assembled onshore, transported to the offshore site, and lifted. This method distributes the weight among the lifts and removes the need for individual blade lifts. This method requires four lifts and was employed at Nysted, Alpha Ventus (Fig. 5.7), Lillgrund, Horns Rev 2, Middelgrunden, Arklow, and Thornton Bank.

    Fig. 5.7
    figure 7

    Installation of an assembled rotor at Alpha Ventus. Source Alpha Ventus

    Full size image
  4. 4.

    Rotor and nacelle in bunny ear configuration. The tower is transported in two pieces and lifted. The nacelle, rotor and two of the blades are assembled onshore and lifted on site. The third blade is lifted independently. The lift capacity for the nacelle, rotor and blade assembly is generally limiting, however, the difference between the tower weight and the nacelle assembly weight is usually small. This method requires four lifts and has been used at Horns Rev (Fig. 5.8), North Hoyle, Barrow, Scroby Sands, and Kentish Flats.

    Fig. 5.8
    figure 8

    Lifting of a nacelle in the bunny ear configuration. Source DONG

    Full size image
  5. 5.

    Tower assembled onshore, rotor and nacelle in bunny ear configuration. The tower is assembled onshore and installed in a single lift. The rotor is installed in the bunny ear configuration and the last blade is installed separately. This method has been used at Princess Amalia and OWEZ and requires three offshore lifts. This method distributes the weights among the two heaviest lifts (nacelle/blade assembly and tower).

  6. 6.

    Entire turbine assembled onshore. The tower, nacelle, rotor, and all three blades are assembled at the dockside or on a barge. The turbine may be lifted from the dock by the installation vessel, or otherwise transported offshore and lifted onto the foundation. This method requires a heavy-lift vessel with at least 500 tons lift capacity and was employed at Beatrice, a demonstration project (Fig. 5.9). The one-lift approach has not been employed at any other project, but various proposals have been suggested for future developments.

    Fig. 5.9
    figure 9

    The Rambiz installing a fully assembled turbine at Beatrice. Source REPower

    Full size image

The method used for turbine installation determines the maximum weight lift required which in turn determines the minimum crane capacity requirement of the vessel. Table 5.1 defines the approximate maximum lift weights for vessels using the six installation methods described. The crane capacity of the existing turbine installation fleet ranges from 100 to 1200 tons. The method used to install turbines is determined by the costs of available vessels, the turbine model, and crane capacity.

Table 5.1 Number of offshore lifts and approximate weights for alternative turbine installation methods and turbines
Full size table

5.2.3 Factors Impacting Installation

Several factors influence turbine installation time, including weather, the number of turbines installed, vessel spread, crew experience, concurrent activities, and distance to port. Turbine installation is sensitive to weather delays due to the height of lifts required and the operating constraints imposed by meteorological conditions.Footnote 1 Distance to port may also be important because there are few options for transporting components. Additionally, turbine installation times will be impacted by the degree of onshore assembly and the installation method, both of which are impacted by the turbine size and the vessel capabilities.

It is possible that new methods will reduce installation time. Installers may develop a more efficient offshore logistics system which will reduce risk associated with offshore transfers and allow the installation vessel to remain on site. Similarly, if installation vessel supply is adequate, installers may seek to develop an assembly-line approach. It has been suggested that the degree of onshore assembly may increase in the future [2], although such opportunities are currently limited by vessel deck space, crane capacity, and the sensitivity of the nacelle. Turbine installation vessels are not designed for installing fully assembled turbines.

5.2.4 Proposed U.S. Turbine Installation Methods

U.S. offshore wind projects have not finalized their method of turbine installation. Cape Wind developers plan to use a self-propelled, elevating installation vessel to carry the components of 6–8 turbines per trip. The tower is to be assembled in two sections, and then the nacelle, hub, and blades will be raised and secured. Preassembly will depend on the vessel specification and size of the deck layout. Bluewater Wind has expressed interest in building one or more self-propelled turbine installation vessels but financing and other relevant details have yet to be worked out. Bluewater’s proposed vessels are similar to those used in Europe and therefore the installation strategy may be similar as well. By contrast, Deepwater Wind plans on building a specialized heavy-lift barge and using Method 6 for installation.

5.3 Cable Installation

There are several methods for offshore wind cableFootnote 2 installation.

  1. 1.

    Simultaneous lay and bury using plow. The plow is pulled by a cable laying vessel or barge and the cable is laid by a turntable placed on the vessel. The plow buries the cable in a trench approximately 2 m deep using a high pressure water jet. The water jet fluidizes the sand or mud and the cable sinks into the trench. This is the most common method of installation, especially for export cables. This method has been used for inner-array cables at Scroby Sands and Rhyl Flats and is proposed at Cape Wind; it has been used for export cables at North Hoyle, Scroby Sands, Barrow, Rhyl Flats, OWEZ, Lynn and Inner Dowsing, and Gunfleet Sands.

  2. 2.

    Simultaneous lay and bury using tracked ROV. This method is similar to Method 1 but uses an ROV instead of a plow. The ROV carries the cable in a spool which limits its use to inner-array cables. This method has been used at North Hoyle, Barrow, and Lynn and Inner Dowsing and is the preferred method when installing cable from the turbine installation vessel.

  3. 3.

    Pre-excavate. Pre-excavate a trench using a backhoe dredge, lay cable in the trench using a cable laying vessel and fill the trench with the dredge. This method may utilize floating cables over the trench via air bags, or may lay cables directly in the trench. This has been used for inner-array and export cables at Lillgrund and Middelgrunden. It was also used for a small section of export cable at Barrow.

  4. 4.

    Lay and trench. Lay cable on the seabed with a cable laying vessel and trench the cable with an ROV (Fig. 5.10). This method has been used for inner-array cable at Kentish Flats, Gunfleet Sands, and Horns Rev 2 and for export cables at Princess Amalia.

    Fig. 5.10
    figure 10

    Tracked ROV. Source Global Marine Power Systems

    Full size image
  5. 5.

    Pull and trench. Pull cables among turbines using a winch and later bury with an ROV or plow. This method is only useful for inner-array connections and was used at Horns Rev.

5.3.1 Inner-Array Cable

Connecting the inner-array cable to the wind turbines is subject to weather and operational problems and may lead to time overruns. For monopiles, a J-tube is attached to the outside to serve as a conduit for the electrical cable. The J-tube extends from above sea level down to or below the mud line. For tripods and jacket structures, the J-tube runs inside or along the foundation. The cable must be fed up through the J-tube via a winch. The process of feeding the cable usually requires divers and/or an ROV and is sensitive to tidal, wave, and current windows.

5.3.2 Export Cable

Export cables may be either high voltage (above 110 kV) or medium voltage (20–40 kV) depending on the capacity of the plant and the length of the export cable. High voltage cable is associated with offshore substations and is larger and heavier than medium voltage cable. Export cables are usually installed by a simultaneous lay and bury method because of its size and weight.

There is considerable variation in the methods used to bring cables to shore. Most frequently, export cables are brought to shore by horizontal directional drilling. A land-based drilling rig is positioned on the beach and drills directionally toward the ocean. The borehole is cased with plastic pipe and serves as a conduit for the cable to be pulled through. The cable is then fed by divers or ROVs from a cable laying vessel positioned offshore through the pipe and pulled onshore by a winch. Alternatively, a cable laying barge may be towed to shore at high tide and allow itself to be beached (Fig. 5.11). The cable laying plow is then pulled down the beach to lay cable. At the next high tide, the barge is refloated and towed out to sea continuing to lay cable toward the turbine array.

Fig. 5.11
figure 11

Cable laying plow and barge. Source Global Marine Power Systems

Full size image

5.3.3 Factors Impacting Installation

The time to install inner-array cabling depends on the number of turbines and layout, soil type, depth of burial, and scour protection requirements. The time to install export cable depends on the location of the onshore substation, soil type, depth of burial, scour protection, and onshore transition. In shallow water, water depth does not play a significant role in installation time. Cable laying on the seafloor is expected to proceed rapidly, but landfall and connecting to an offshore substation will involve additional time.

The process of laying cable is affected by the weight and length of the cable. Inter-turbine cables are generally transported and installed in lengths approximately equal to the distance between turbines (usually less than 800 m), while export cables are at least as long as the distance to shore (3–60 km). As a result, a length of inner-array cable may weigh 10–20 tons, while an export cable may weigh 500–700 tons for a near-shore (10 km) wind farm. The sizes and weights of cable impact the vessels required and the installation time.

Burial depth is influenced by soil type, the probability of scour, and government regulations. Increasing burial depth increases the likelihood of unsuitable subsurface conditions. Scour protection may be required to ensure the necessary depth is maintained.

The method and vessels used represent tradeoffs and impact the installation time. Installation is fastest when using dynamically positioned vessels because the mooring spread does not need to be frequently repositioned. If Method 3 is used, the time that the cable laying vessel requires would be short, but the total time to install cables would be long due to the time needed to excavate and fill the trench. Likewise, an ROV operated from a turbine installation vessel might not be the most time-efficient solution, but the fact that it allows a single vessel to complete two jobs simultaneously could make it preferred over alternatives.

5.3.4 Proposed U.S. Cable Installation Methods

In Cape Wind, developers plan on installing the inner-array cable using jet plowing with a support tug and barge. Scour mats and rock armor will be used in some places and will require diver support. The export cable will make landfall via a horizontal borehole drilled from the land toward the offshore exit point. A temporary cofferdam will be utilized and backfilled after the operation is complete.

5.4 Substation Installation

Offshore substations are placed on monopile, jacket, or gravity foundations. The transformer is assembled onshore, lifted off the dock by a heavy-lift vessel, and transported to site (Fig. 5.12). After the transformer is placed on the foundation and secured, finishing work is performed.

Fig. 5.12
figure 12

Installation of an offshore substation. Source DONG

Full size image

5.5 European Installation Time Statistics

The purpose of this section is to evaluate and synthesize installation experiences of European wind farms. Our objective is to quantify and describe work activity statistics and correlations to inform and baseline future U.S. development.

5.5.1 Data Source

Table 5.2 shows the primary sources for installation data and identifies the best published descriptions. For some aspects of installation, no information, or only poor quality information, was available. For other aspects, detailed and consistent information was reported. Installation times are reported across multiple activities and were not normalized for distance to staging area, weather disruptions, and similar events. The unit time statistics include the impact of these factors and represent the total time to install the system rather than the time to install any single component.

Table 5.2 Sources of information on installation activities at select offshore wind farms
Full size table

5.5.2 Foundation

Table 5.3 summarizes information on the time required to install monopiles and transition pieces. Foundation installation, including transit time, weather delays, and transition piece placement, takes on average 3.7 days per pile with a standard deviation SD = 2.1 days. Installation time ranged from 1.8 to 8.6 days per foundation. Excluding Arklow (a small, seven turbine project), the average time per foundation decreased to 3.3 days per monopile (SD = 1.5). In two cases, monopiles were driven by one vessel and transition pieces were installed by a second vessel. In these cases, it is the number of boat daysFootnote 3 rather than the total time that is the meaningful statistic. After adjusting the total installation time for these cases, the average time increased to 4.0 boat days per foundation (SD = 2.0). Excluding Arklow, average time per foundation was 3.6 boat days per monopile (SD = 2.1).

Table 5.3 Offshore wind farm installation requirements—foundations
Full size table

Installation rates as a function of project size are shown in Table 5.4. For projects with 30 foundations or less, 4.6 boat days per foundation are required, decreasing to 3.8 boat days per foundation for 30–60 foundation installations, and 2.6 boat days per foundation when 60 or more foundations were installed. There are indications of scale economies, but detailed statistical analysis is not meaningful due to the small sample size.

Table 5.4 Rate of foundation installation by number of foundations
Full size table

5.5.3 Turbine

Table 5.5 depicts the time required to install turbines. The average time to install a turbine was 4.1 days (SD = 3.0). In six of the 18 cases, two vessels were employed and so activity time was normalized on a boat day basis. The average time to install a turbine was 5.7 boat days (SD = 5.7). When small projects were excluded (Thornton Bank, Alpha Ventus and Arklow), the average dropped to 4.0 days per turbine (SD = 2.6). In some cases, turbines were installed in under 2 days per turbine including at Lynn and Inner Dowsing, Horns Rev 2, Nysted, Lillgrund, and Burbo Bank.

Table 5.5 Offshore wind farm installation requirements—turbines
Full size table

The relationship between the installation rate and method of installation is presented in Table 5.6. Methods 1 and 2 required less than 2 boat days per turbine; Methods 3, 4, and 5 were associated with longer average installation times. This trend is unexpected and may reflect the small sample size.

Table 5.6 Rate of turbine installation by installation method
Full size table

Table 5.7 shows the relationship between the installation rate and the total number of turbines installed. As in foundation installation, a general trend of faster installation with increasing turbine number is observed, and provides evidence of learning. Again, the sample sizes are too small and the standard deviations are too large to make any definitive statement regarding turbine number and installation time.

Table 5.7 Rate of turbine installation by number of turbines
Full size table

5.5.4 Cable

Cable can be laid rapidly but the connection points at turbines and pull-ins to shore are subject to weather and operational delays. Table 5.8 depicts the total time required to install export and inner-array cables and the installation time per km of cable. Export cables were laid at an average rate 0.7 km/day (SD = 0.4) and inner-array cables were laid at an average rate of 0.3 km/day (SD = 0.1). Export cables rates ranged between 0.2 and 1.4 km/day; inner-array cable rates ranged from 0.1 to 0.6 km/day.

Table 5.8 Offshore wind farm installation requirements—cables
Full size table

Rate estimates are conservative and uncertain. In general, reports of vessel utilization for cable laying are not as common as those for foundation and turbine installation, and so the sample size is smaller. Distance to port, burial depth,Footnote 4 and scour protection are not distinguished in the unit time statistics.

Table 5.9 shows the installation rate by total cable length for inner-array cables. The rates are fairly uniform by type and do not vary significantly with distance or within category. In Table 5.10, export cable installation time by voltage and distance is depicted. Medium voltage cable is smaller and lighter than high voltage cable and has a faster lay rate and as distance increases, so does the lay rate. This probably reflects the fixed time component of the installation of the onshore transition. Export cable has a faster lay rate than inner-array cable which is likely due to the smaller number of connections that have to be made.

Table 5.9 Inner-array cable installation rate by distance
Full size table
Table 5.10 Export cable installation rate by voltage and distance
Full size table

5.5.5 Substation

There is little reliable data on substation installation. The best record of the installation of a substation is from Thanet, where the jacket and substation were installed by the Stanislaw Yudin in four days. The Cape Wind EIS states that installation of its substation will require one month, but much of this time will be spent doing finishing work, and heavy-lift vessel support will only be required for a few days during this time. Foundation installation requires approximately the same amount of time and same vessels required for monopile or jacket installation. We expect a substation monopile foundation to take approximately four days to install and slightly longer if a jacket is used. Placement and securing the substation could be accomplished in as little as one day. However, since a slow moving heavy-lift vessel is required to travel to the site, one or more days would need to be added, depending on the distance to the staging area.